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November 5, 2024

Pipeline Developer Asks Massachusetts to Order Route Access

By William Opalka

Tennessee Gas Pipeline is asking Massachusetts regulators to grant it access to more than 400 properties whose owners have refused to cooperate with the company as it prepares for construction of the Northeast Energy Direct project.

tennessee gas pipeline
Opponents of the Northeast Energy Direct pipeline marched in protest last week. (Source: PopularResistance.org)

In a petition to the Department of Public Utilities, the pipeline said access is needed to conduct “civil, archeological and cultural resources, wetlands and waterbody delineation, and endangered or rare species” surveys as part of the project’s review by federal regulators (16-03).

The order would be “preliminary to eminent domain” actions if property owners continue to refuse permission. The project would transport natural gas from Pennsylvania into New England. (See Northeast Energy Direct Files for FERC Certificate.)

“Tennessee has in good faith made efforts to obtain survey permission from owners of survey properties, including sending at least two letters requesting survey permission and attempting to discuss the request in person or via telephone,” the petition says. “Many survey property landowners have granted Tennessee permission to conduct the surveys.”

However, 408 have “either expressly refused to grant Tennessee permission to conduct the surveys or not granted Tennessee permission to conduct the surveys,” the petition says.

“These landowners are minding their own business and seeking to simply live their lives in peace. We are working to ensure that they have the legal guidance they need to deal with this assault on their privacy and unjustified intrusion on their property,” Kathryn Eiseman, president of the Pipe Line Awareness Network for the Northeast, said in a statement.

The company, a unit of Kinder Morgan, said it needs a 400-foot wide corridor along the project’s route. It said that Massachusetts law allows granting of the order before FERC gives final approval for the project.

The department has scheduled six hearings statewide on the company’s request, starting in Pittsfield on March 29. Written comments will be accepted through May 6.

PJM MRC/MC Preview

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday, January 28, 2016. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM Manuals (9:10-9:25)

Members will be asked to endorse the following manual changes:

  1. Manual 27: Open Access Transmission Tariff Accounting. Changes allow for network service peak load values submitted by electric distribution companies to be scaled by the eRPM auction software if they do not add up to the annual network service peak load allocation for the area.
  2. Manual 38: Operations Planning. Changes resulting from annual review correct typos, revise terms for consistency and update PJM reliability study procedures.
  3. Manual 40: Training and Certification Requirements. Implements a new process requiring operators or dispatchers not in compliance be removed from their shifts. Also establishes a compliance score scheme that will trigger a violation notice to the company and potentially FERC. (See “New Operator Compliance Rules to Take Effect Feb. 1,” PJM Operating Committee Briefs.)

3. Energy Market Offer Cap (9:25-9:45)

Tariff and Operating Agreement changes provide clarification conforming to FERC’s order that revisions to the energy market offer cap exclude the 10% adder from cost-based offers more than $2,000/MWh. The committee is being asked to endorse the revisions on first read due to time-sensitivity. (See PJM Members OK $2,000/MWh Energy Market Offer Cap.)

4. Virtual Transactions (9:45-10:00)

A proposed problem statement and issue charge address the nodes at which virtual transactions may be made. The issue stems from a report PJM published in October, “Virtual Transactions in the PJM Energy Market,” that identified instances in which existing market rules allow virtual transactions to be used in a manner that do not add value to the market commensurate to the costs imposed by them. (See PJM Suggests Changes to Virtual Transactions.)

5. Distributed Battery Storage in PJM Markets (10:00-10:15)

Drew Adams of battery maker A.F. Mensah will propose a problem statement and issue charge to study establishing a clear path to market in PJM for distributed battery storage systems.

6. Unit Commitment (10:15-10:30)

Barry Trayers of Citigroup Energy will propose a problem statement and issue charge to investigate separating financial day-ahead obligations from the physical unit commitment.

7. Capacity Performance Cost Allocation (10:30-10:45)

PJM is presenting a problem statement and issue charge asking stakeholders to review whether the Reliability Pricing Model method of cost allocation should be revised. In its Capacity Performance filing, PJM proposed changing the method by which it allocates the cost of procuring capacity. Given the protests and comments received, however, it asked FERC to postpone ruling on that component until the matter could be addressed through the stakeholder process.

8. Seasonal Capacity Resources (10:45-11:00)

Members will be asked to endorse a problem statement and issue charge regarding incorporating seasonal resources into the Capacity Performance construct. Capacity Performance rules allow aggregation of seasonal resources to convert them into “synthetic” annual resources but none were submitted in the first Base Residual Auction involving CP. Stakeholders will be asked to consider whether Tariff language can be improved or developed to encourage seasonal resources to participate in the market.

9. Voltage Threshold (11:00-11:15)

Revisions to the Operating Agreement would exempt transmission reliability projects of less than 200 kV from the competitive proposal windows. Such projects are almost always assigned to incumbent developers, and PJM said the change would enable its engineers to focus on problems more likely to result in a competitive greenfield project. (See “Voltage Threshold will Exempt Some Projects from Proposal Window,” PJM Planning Committee and TEAC Briefs.)

10. Long-Term Firm Transmission Service Task Force (11:15-11:25)

Proposed changes to Manual 14A: Generation and Transmission Interconnection Process and 14B: PJM Regional Transmission Planning Process would modify long-term firm transmission service methods. Revisions to 14A would add a cost allocation obligation for new service requesters toward facility upgrades. Changes to 14B describe the baseline and new service request studies, the distribution factor and rating limit allowed to contribute to flowgates and the interaction of baseline and new serve request studies on constraints identified in the capacity import limit studies.

11. PAR Task Force (11:25-11:35)

Other changes proposed for Manual 14A would make clear that phase angle regulator (PAR) technology is eligible for transmission injection rights. (See “Phase Angle Regulators Qualify for Transmission Rights,” PJM Planning Committee and TEAC Briefs.)

12. Governing Documents Enhancement & Clarification Subcommittee (GDECS) (11:35-11:45)

Proposed revisions to the Tariff, Operating Agreement and Reliability Assurance Agreement offer clarifications and consistency for certain terms.

Members Committee

Endorsements(1:25-2:40)

  1. Energy Market Offer Cap(2:10-2:30)

See related item above.

  1. Liaison Committee (LC) Charter (2:30-2:40)

Members will be asked to approve changes to the Liaison Committee charter. The revisions provide for an LC meeting with the board or the second General Session meeting in a calendar year to be canceled upon a super-majority vote of the sector whips. The Members Committee would need to receive three business days’ notice of such a vote. Any sector voting not to cancel a meeting would be required to provide at least one topic to be discussed.

FERC Postpones Action on Supply Chain Protections

FERC on Thursday gave final approval to revisions to seven critical infrastructure protection (CIP) reliability standards.

The final rule approves NERC’s proposed requirements for personnel and training, physical security of the grid’s cyber systems and information protection (RM15-14).

It requires NERC to make changes addressing protection of transient electronic devices, such as thumb drives and laptop computers, at low-impact Bulk Electric System cyber systems and protections for communication network components between control centers. It also requires NERC to refine its definition for low-impact external routable connectivity and to conduct a study assessing the effectiveness of CIP remote access controls, the risks posed by remote access-related threats and vulnerabilities, and appropriate controls.

Supply Chain Protections not Included

The order does not include a provision in the commission’s July Notice of Proposed Rulemaking that would have required NERC to develop requirements for supply chain management for control system hardware, software and services. (See FERC Seeks Supply Chain Protection Against Cyber Threats.)

The commission said it will consider action on that issue based on advice from staff following a Jan. 28 technical conference.

A supply chain standard would be only the third time the commission has ordered NERC to initiate a standard, following standards addressing geomagnetic disturbances and physical security.

The commission’s supply chain concerns were prompted by two malware campaigns against vendors of industrial control systems.

The final rule takes effect 65 days after publication in the Federal Register.

Rich Heidorn Jr.

Company Briefs

EnsyncEnergySourceEnsyncEnSync Energy Systems of Menomonee Falls, Wis., has set up a Hawaii hydroponic and aquaponics company to detach from the grid entirely. Using an energy management system composed of solar generation and batteries, Mari’s Garden in Mililani, on Oahu, is operating the water pumps for its hydroponic and fish farming operation off the grid.

The system uses a 25-kW photovoltaic unit and 40 Aquion battery stacks to store 92 kWh of energy. Mari’s Garden said it plans to expand the PV system to 75 kW later this year.

More: Pacific Business News; EnSync Energy Systems

Richey Named Site Vice President at FE’s Beaver Valley Nuclear Station

firstenergyFirstEnergy has named Marty Richey the site vice president at the Beaver Valley Nuclear Power Station in Shippingport, Pa. He takes the place of Eric Larson, who will represent FirstEnergy Nuclear Operating Co. as a loaned executive to the Institute of Nuclear Power Operations in Atlanta.

Richey, a 27-year industry veteran, most recently was plant manager at Entergy’s Waterford Nuclear Generating Station in Killona, La.

He also is a veteran of the U.S. Navy Nuclear Power Program, where he was a mechanical operator and engineering lab technician.

More: FirstEnergy

Japanese Company’s New Power Storage System Goes Online

SumitomoSourceSumitomoSumitomo Corp. is starting up its new power storage system, Willey Battery Utility, in Hamilton, Ohio, which will participate in PJM’s frequency regulation market.

“As a developer of wind and solar power plants which are unavoidably intermittent generation sources, we think it is quite important that we also contribute to the stabilization of power grids through balancing services,” said Nick Hagiwara of the Sumitomo Corporation of Americas.

The 6-MW, 2-MWh system was developed by RES Americas. It is the Japanese conglomerate’s first investment in a large-scale, stand-alone battery project in the United States.

More: Sumitomo Corp.

Plastic Sheet Could Provide Solution to Battery Overheating

A Stanford University chemical engineer has invented a plastic sheet that can be inserted into lithium ion batteries to prevent overheating.

The sheet is embedded with carbon-coated nanoparticles of nickel that allow it to conduct electricity. However, it expands when it heats up, pulling apart the nanoparticles so they no longer conduct electricity.

When the sheet cools down, the battery begins operating again.

More: Delaware Public Media

PSEG Solar Source Acquires Solar Projects in Ca., Utah

PSEG SolarPSEG Solar Source is increasing its solar capacity to 214.6 MW with the $110 million acquisition of projects in California and Utah from Colorado solar developer juwi Inc.

The 3.9-MW PSEG Lawrence Livermore Solar Energy Center is being built at the Lawrence Livermore National Laboratory, about 45 miles east of San Francisco.

The 62.7-MW PSEG Pavant II Solar Energy Center will be located about 110 miles south of Salt Lake City.

More: The Philadelphia Inquirer

ComEd Receives $4M Grant from DOE SunShot Initiative

COMED (EXELON) logoThe U.S. Department of Energy has awarded $4 million to Commonwealth Edison to create solar and battery storage technology in its microgrid demonstration project in the Bronzeville neighborhood in Chicago. The grant is part of the department’s SunShot Initiative.

The project is a precursor to ComEd’s proposed development of six microgrids in Illinois.

“Distributed generation is the future of the electric grid,” said ComEd President and CEO Anne Pramaggiore. “The microgrid demonstration we are building in Bronzeville is a blueprint for other utility-owned microgrids around the country.”

More: Commonwealth Edison

Duke Says it Set Solar Record in NC

Duke Energy logoDuke Energy says it installed more than 300 MW of solar generation in North Carolina this year, eclipsing its record of 160 MW the year before.

Duke last year spent $500 million to build four solar farms in the state with a capacity of 141 MW and bought 150 MW more.

The company said it plans to build another 75 MW of solar this year. The company expects North Carolina to rank second behind California for utility-scale solar construction in 2015.

More: The Charlotte Observer; Duke Energy

Houston Gas Firm Lays off 600 in Fayetteville Shale

southwesternenergysourcesweHouston-based Southwestern Energy said it is laying off 1,100 employees, including 600 throughout its Fayetteville Shale operations in Arkansas, amid a steady decline in natural gas prices.

The cuts, set to be complete by the end of the first quarter, will leave 560 employees in the central Arkansas natural gas play. Southwestern said the “organizational changes” are necessary to be competitive in a “low gas price environment.”

Natural gas at regional hubs was trading around $2.13/MMBtu on Thursday, down from a 52-week high of $3.47. Southwestern reported a third-quarter net loss of $1.8 billion, or $4.62/share.

More: Arkansas Business

Enel Green Power Building 7th Wind Farm in Oklahoma

EnelGreenPowerSourceEnelEnel Green Power North America has started construction on a 108-MW wind farm southwest of Oklahoma City, its seventh such project in Oklahoma.

Enel’s Drift Sand project is expected to be finished by the end of the year. The electricity will be sold to Arkansas Electric Cooperative Corp. under a long-term power purchase agreement.

Enel, whose first Oklahoma project was finished at the end of 2012, is now the state’s second-largest wind farm operator, with 958 MW. The $180 million Drift Sand wind farm will push the company to 1,066 MW of wind capacity in Oklahoma.

More: The Oklahoman

Peabody Energy Pulling out of Prairie State Energy Campus

PeabodyEnergySourcePeabodyPeabody Energy announced it is selling its share of the troubled Prairie State Energy Campus in Missouri to Wabash Valley Power Association for $57 million.

Peabody, which is being pressured by the downturn in the coal industry, said it was selling its 5.06% stake in the 1,600-MW coal-fired generating station about an hour southeast of St. Louis as part of its move to shed noncore assets.

The price of the generating station skyrocketed amidst cost overruns and missed deadlines, and stands at about $4 billion now. The plant has shown steadily increasing performance, however.

More: St. Louis Post-Dispatch

Kinder Morgan Plans Spending Cuts After Q4 Losses of $637 Million

Kinder Morgan said last week that it planned to cut spending after posting a net loss of $637 million for the fourth quarter.

The company attributed the loss to higher taxes and interest expenses, coupled with a decline in market values. The company showed a net profit of $126 million for the same period a year ago. For the full year of 2015, Kinder Morgan reported net income of only $311 million, compared with nearly $1.03 billion in 2014.

The company also cut its capital budget for 2016 to $3.3 billion from its previous estimate of $4.2 billion. “What we’re trying to do is really make sure that we’re investing capital on the highest-return opportunities that we have, make sure that we’re fulfilling our commitments and delaying spend where it can be delayed or deferred, and taking on partners where it makes sense for us to take on partners,” CEO Steve Kean said Wednesday.

More: Reuters; Natural Gas Intelligence

Piedmont Gas Shareholders OK Duke Energy Deal

PiedmontNatGasSourcePiedmontShareholders of Piedmont Natural Gas approved the sale of the company to Duke Energy for $4.9 billion. Of about 81 million eligible voting shares, about 54 million voted in approval, with 1.1 million against.

Piedmont will retain its name and keep its Charlotte, N.C., headquarters. Duke has said that it does not expect many job losses as a result of the acquisition. Piedmont has about 1,900 employees.

Both Piedmont and Duke Energy are major partners in the proposed $5 billion Atlantic Coast Pipeline, a natural gas pipeline that is to run from West Virginia to markets in Virginia and North Carolina.

More: The Charlotte Observer

MISO Planning Advisory Committee Briefs

Aiming to prevent claims of preferential treatment under its new competitive transmission process, MISO last week released a formal protocol prohibiting bidders from contacting any MISO staff member directly about requests for proposals.

The rules were released as MISO prepares to receive bids on its first competitive transmission project, the Duff-Coleman 345-kV upgrade. (See MISO Seeks Bids on Duff-Coleman Project.)

Brian Pedersen, MISO’s senior manager of competitive transmission services, said the RTO created a new email address (TDQS@misoenergy.org) so transmission developer applicants wouldn’t contact any MISO staffer.

miso

“We’re moving from a workshop environment to a competitive bid environment … and we want to make sure people know how to communicate appropriately,” Pedersen said. “Once we receive proposals, MISO will only respond to procedural questions. … We’re not going to respond to any substantive questions about the [evaluation] and where we’re at in it.”

MISO said it will publicly post a list of received questions and its responses on the MISO competitive transmission webpage.

Meanwhile, stakeholders will continue working into spring on changes to Business Practice Manual 27 to align it with Tariff changes approved by FERC in November regarding the qualification and selection of competitive developers and the pro forma developer’s agreement (ER15-2657, ER15–2658). Redline changes will be discussed at the March and April Planning Advisory Committee meetings. MISO hopes to make the changes effective by May 1.

BPM Changes Completed for Expedited Project Review

MISO presented stakeholders with BPM changes to replace the out-of-cycle review process with the new expedited review procedure.

MISO will now post all valid expedited requests within two weeks of receipt and notify stakeholders of such requests.

The final BPM language concludes almost a year of discussion on the topic, after stakeholders raised objections to Entergy’s Lake Charles transmission upgrades last February. Some critics questioned whether Entergy was seeking to circumvent the competitive bidding process. (See MISO Seeks Stakeholder Input on Out-of-Cycle Process amid Entergy Controversy.)

“We’ve not had an expedited review of the expedited project review,” joked Matt Tackett, a principal adviser for MISO, during a presentation of the final BPM language.

Sean Brady, Wind on the Wires’ regional policy manager, thanked Tackett for not “rushing” stakeholders through the review process. “I really appreciate that,” he said.

MISO said it would not solicit any further input on the BPM language but would delay posting it until the PAC decides whether to endorse it at its February meeting.

MISO Planning Confidentiality, Notification Changes to Attachment Y Procedure

MISO will require more notification and relax some confidentiality rules concerning generator suspensions and retirements and system support resources planning under Tariff changes outlined to the PAC.

The proposed changes would affect the Attachment Y process, which ensures MISO has time to identify transmission needs resulting from the loss of a generator.

The changes would subject black start units and pseudo-tied generators to Attachment Y requirements that units intending to retire or suspend operations provide at least 26 weeks’ notice.

In addition, information made public by a generator owner will no longer be considered private, and information won’t be confidential after a retirement date has passed.

Some public interest organizations said MISO should make Attachment Y notices public upon their filing, as in PJM. MISO said a 2012 FERC order directed the RTO to keep Attachment Y notices and study results confidential for units that do not qualify as an SSR (ER12-2302).

MISO may also require a new Attachment Y notice 26 weeks prior to the change in status of a SSR unit wishing to retire or alter its agreement, MISO’s Neil Shah said.

Several market participants said that the current 36-month cumulative time limit on generator suspension in a five-year period and the 26-week notice requirement would need to be adjusted under MISO’s proposed switch to a four-month summer and an eight-month winter capacity construct. Shah said that suggestion will be considered only once capacity market changes are finalized.

Generation owners would have to file directly with FERC to determine how much they will be compensated for fixed costs under an SSR and complete either an OASIS posting or a FERC filing to terminate interconnection rights. Suspended generators unable to return to service at the end of suspension period will be considered retired and have their interconnection rights terminated.

Shah said MISO’s decision to change the process is based on experience gained since 2012. Tariff changes will be filed by Feb. 26; MISO is requesting an effective date of May 1.

Work on MTEP17 Futures to Continue Through September

Work on changes to the Transmission Expansion Plan futures process will last through the first three quarters of 2016, Matt Ellis from MISO’s policy studies unit told the PAC. “This is really more a teaser for what’s to come in 2016,” Ellis said of his presentation.

MISO said the new futures process, set to take effect beginning with MTEP17, will use familiar procedures. As with previous MTEPs, final decisions will be made during PAC meetings, while technical details will be hashed out in workshops.

miso

MISO plans to review its resource siting methodology for use in PROMOD models beginning in March and finalize it in July. (See “CPP to Play Role in Reworked Futures Development,” MISO Planning Advisory Committee Briefs.) “We’ve had basically the same siting information for years, so we’ve worked time into the process for re-siting,” Ellis said.

The RTO said it wants to employ a scenario-based analysis with the possibility for many outcomes rather than the least-cost plan under a single scenario. “The scenarios should simulate likely or plausible real-life future system conditions and provide an envelope of outcomes that is significantly broad, rather than a single expected forecast,” MISO wrote.

MISO is hoping to review draft results of the new futures process by the August PAC. “We want to wrap up the whole MTEP17 futures planning process by September,” Ellis said.

Ellis is asking for feedback by Feb. 10 on MISO’s proposed timeline, which he says is subject to change.

Amanda Durish Cook

FERC Outlines Principles for Clean Power Plan Analyses

By Rich Heidorn Jr.

FERC staff last week released a white paper identifying what it called “four guiding principles” that may help RTOs and other transmission planning entities analyze compliance with EPA’s Clean Power Plan.

Although the commission has no direct role in CPP compliance, it may be called on to evaluate the impacts of plant retirements and other responses on reliability.

Staff said modeling of the CPP should address: transparency and stakeholder engagement; study methodology and interactions between studies; study inputs, sensitivities and probabilistic analysis; and tools and techniques. The white paper borrows from a 2015 report by M.J. Bradley & Associates cited by EPA.

clean power plan
Alliant Energy’s coal-burning Edgewater Generating Station (Source: Alliant Energy)

“Incorporating these guiding principles in the modeling of the CPP compliance plans is one way to promote a robust analysis of the reliability impacts of the CPP,” the commission said, adding that it may conduct additional technical conferences on the rule. (See MISO, SPP Stakeholders Developing Trading Plan to Comply with EPA Carbon Rule.)

“State-by-state variations in compliance approaches may add additional uncertainty and complexity, particularly for transmission planning entities that cover multiple states or states with multiple transmission planning entities,” FERC said. “Further, the use of inconsistent models, or inconsistent modeling inputs, may suggest reliability problems where none exist, or may mask problems that do exist. If models and modeling inputs are not transparent, it will be difficult for stakeholders, state commissions, planning authorities or the commission to identify, understand or address potential problems.”

FERC said the impacts of CPP compliance plans can be evaluated through a combination of studies, including resource adequacy, production cost, integrated gas-electric systems simulations and power flow and transient stability analyses.

“Incorporating the results of one study into a subsequent study can result in a more robust analysis,” the white paper says. “For example, the results of a resource adequacy analysis can be used to define the assumptions for the composition of the generation fleet used in a production cost or natural gas infrastructure study. This iterative process can lead to more robust results than using static assumptions.”

It also called for use of new tools to measure the impact of increased renewable and natural gas generation.

New England Generators Appeal FERC Capacity Market Orders

The New England Power Generators Association last week asked a federal appeals court to review three FERC orders related to the operation of ISO-NE’s Forward Capacity Market.

NEPGAFERC in November denied rehearing of complaints made concerning orders related to ISO-NE’s Pay-for-Performance program and the peak energy rent adjustment.

The appeals were filed in the D.C. Circuit Court of Appeals (16-1023, 16-1024).

The first order directed ISO-NE to adopt a modified version of its proposed market design (ER14-1050, EL14-52-001). FERC also denied rehearing on a compliance filing (EL14-52-002).

FERC also denied rehearing of a NEPGA complaint that alleged that the interaction between the penalty factor and ISO-NE’s peak energy rent mechanism is unjust and unreasonable (EL15-25). (See FERC Denies Rehearings on ISO-NE Pay-for-Performance.)

William Opalka

Federal Briefs

GridWiseSourceGridWiseThe 3rd Annual Grid Modernization Index, a ranking of the progress of states and D.C. toward developing a modernized electric grid, once again scores California on top, followed by Illinois, Texas, Maryland and Delaware.

The rankings by the GridWise Alliance advocacy group are based on survey data from June through October 2015 that tracks grid modernization policies, investment levels and activities.

“Electricity lies at the heart of our economy, and it must evolve to serve the needs of an increasingly low-carbon, always-on, digital economy,” said Steve Hauser, CEO of the GridWise Alliance. “We are pleased to see continued progress across the country this year, but the survey shows that we are just getting started.”

More: GridWise Alliance

Scientists Declare 2015 as Hottest on Record

NOAASourceWikiScientists said that 2015 was the world’s hottest year on record, breaking 2014’s record, and it was the second-warmest on record for the lower 48 states.

“The globally averaged temperature over land and ocean surfaces for 2015 was the highest among all years since record keeping began in 1880,” said the National Oceanic and Atmospheric Administration’s National Centers for Environmental Information. “During the final month, the December combined global land and ocean average surface temperature was the highest on record for any month in the 136-year record.”

The globally averaged land surface temperature was 2.39 F above the 20th century average, the NOAA report said.

More: The New York Times

EIA Predicts Short-Term Increase in Renewables

EnergyInformationAdminSourceEIAThe Energy Information Administration said it expects renewable energy sources to increase by about 9.5% in the U.S. in 2016 but said it doesn’t expect much of a boost in subsequent years because of the recently extended energy tax credits.

EIA said that “most plants that will enter service in 2016 are already being developed. Impacts in 2017 depend on how many wind and solar projects are already in the development queue but not yet under construction.”

The report also anticipates a 4.6% increase in hydro generation this year because of increased rainfall, particularly in the Pacific Northwest.

More: Energy Information Administration

Obama Administration Moves to Stop Methane Leaks

Department of the Interior sealThe Department of the Interior on Friday unveiled regulations that will mandate that energy companies reduce methane leaks at wells drilled on federal or Native American land. It is yet another attempt by the Obama administration to take steps to combat climate change.

The leaking or venting of methane from federal or Native American land released about 375 billion cubic feet of methane into the atmosphere between 2009 and 2014, according to the government. The new regulations would impact more than 100,000 oil wells that currently produce about 10% of the country’s natural gas.

The oil and gas industry oppose the regulations, which would put new limits on venting and flaring excess natural gas, a practice used to reduce pressure on oil wellheads. The regulations will also call for more frequent inspections to check for leaks. The regulations represent the first major update of such controls in 30 years.

More: The Washington Post

Duke CEO Good Says CPP Will Shift Focus to Nuclear

Photo of Duke CEO Lynn GoodDuke Energy CEO Lynn Good said the federal Clean Power Plan, with its stringent emissions regulations, is going to force many of the nation’s coal-fired plants to close. Good said she thinks the CPP and carbon limits will eventually shift the spotlight to nuclear energy.

Speaking at the CEO Series of the World Affairs Council of Charlotte, in North Carolina, Good noted that there is a resurgence in nuclear power in China, where 25 reactors are under construction. Five are under construction in the U.S. Most new American power plants use cheap natural gas, which reduces carbon emissions compared to coal, but doesn’t completely eliminate greenhouse gases as nuclear power does.

“I hope nuclear becomes a part of the conversation, at the right time when we recognize the importance of that resource,” she said. “I hope we can work that out as a country and figure out how we are going to put nuclear in the mix.”

More: Charlotte Business Journal

Trans-Peco Pipeline Earns OK in FERC Environmental Study

A FERC environmental assessment has determined that Energy Transfer Partners’ Trans-Peco pipeline, which would deliver natural gas from Texas to Mexico, would have no detrimental effect on the environment.

The natural gas exported to northern Mexico would replace coal as a power plant fuel, but opponents vow they will continue to fight the project. Other state and federal permits are still needed before it can go forward.

“At a personal level, I am outraged over the FERC’s decision,” said Coyne Gibson, a leader in the opposition movement. “At best, this represents a complete and total failure of a federal regulatory agency’s oversight responsibility under the law.”

More: Big Bend Now

FERC Approves 4 Hydro Projects Along Yazoo Basin

FERC has approved licenses for four projects to be built at flood control facilities along the Yazoo River Basin in Mississippi, according to the projects’ developer, FFP New Hydro.

The company, which is a subsidiary of US Renewables Group, said it expects to begin construction in 2017 and have all four units go into operation in 2018. The four facilities would have a capacity of 33.3 MW. They would all be located at dams owned and operated by the U.S. Army Corps of Engineers.

“The development of the Yazoo River Basin hydropower projects will represent an investment of more than $80 million in the state of Mississippi, creating hundreds of jobs during construction, operations and maintenance,” said FFP New Hydro CEO Ramya Swaminathan.

More: Hydroworld

Six Missouri River Dams Yield Tepid Energy Production in 2015

The U.S. Army Corps of Engineers is reporting that electricity generation from the Missouri River’s six dams in the Dakotas, Montana and Nebraska fell below average in 2015. The cause is attributed to a reduced water flow because water is being retained in upstream reservoirs.

According to the corps, the six dams produced 8.5 billion kWh last year, compared to 9.6 billion kWh in 2014. Since 1967, the dams have generated an average 9.3 billion kWh annually. Mike Swenson, a corps engineer in Omaha, said 9.6 billion kWh of electricity production is expected from the dams in 2016 based upon rainwater runoff estimates.

More: The Republic

MISO: Mass-Based CPP Plan 1/3 Cost of Rate-Based

By Amanda Durish Cook

CARMEL, Ind. — Mass-based compliance with the Clean Power Plan would cost less than one-third as much as a rate-based method by 2030, according to modeling by MISO.

MISO found that the price disparity between rate-based compliance, which limits emissions in tons per megawatt-hour, and mass-based compliance, which caps emissions in tons per year, increases over time due to the mass-based method’s increased flexibility under emissions trading.

By 2030, production-based compliance costs are expected to reach about $17 billion under a rate-based plan, while mass-based compliance is  estimated at about $5 billion, according to the near-term analysis presented at Wednesday’s Planning Advisory Committee meeting. This includes the expense of generation, interchange and emissions, excluding additional transmission and pipeline infrastructure, and other capital costs.

MISO has said that individual states won’t shoulder the burden equally.

MISO Will be Compliant in First Years

Jordan Bakke, policy studies lead at MISO, said rate-based compliance is centered around adding zero-emission resources while mass-based compliance requires also removing emission-heavy generation. Early compliance targets are slated to be met through MISO states’ existing renewable portfolio standards and natural gas’s replacement of coal generation, but additional changes will be needed to continue compliance.

clean power plan
MISO believes that early compliance targets are met through renewable portfolio standards and coal to gas re-dispatch, but comprehensive planning needs to start today to meet increasingly stringent compliance targets in the mid-2020s.

“The planning that has already occurred will only get us so far,” Bakke said. Compliance costs would rise significantly in the “mid- to late 2020s,” he said, after MISO’s existing generation mix fails to carry it through increasingly stringent emissions goals.

The threats to MISO’s coal fleet are less severe in a regional mass-based approach. The analysis forecasts six coal units to be idled by 2030 under mass-based plans, versus nine under rate-based compliance.

With either option, the grid operator said it would need new zero-emission resources to temper the price of CO2, which is expected to rise from about $20/short ton in 2022 to about $40/short ton by 2030 under mass-based compliance and almost $140/short ton under a rate-based regime.

“Coal unit capacity factors decrease greatly over time under the CPP, more dramatically with a rate-based implementation,” MISO wrote. On the other hand, MISO has suggested that mass-based compliance might require less capital investment because system dispatch won’t have to undergo as many changes. The RTO said the low capacity factors, even using a business-as-usual measurement, show coal units won’t be economically viable by 2022 or 2030.

66 Cases Modeled

Bakke said that the near-term modeling ran 66 cases with differing changes in capacity and either mass- or rate-based compliance: three business-as-usual scenarios in the years 2022, 2025 and 2030; 39 instances of business-as-usual resources but with CPP constraints applied; and 24 runs using alternative resource scenarios combined with CPP constraints. The three business-as-usual cases, which rely heavily on coal generation, would not meet emissions targets, while both categories that use CPP constraints would.

The study assumes a liquid carbon emissions market and that all states choose either mass- or rate-based plans. Bakke said further modeling will be needed if states decide to use a mix of rate-based and mass-based trading.

MISO said it assumed a $4.67/MMBtu natural gas price for 2015. In addition to modeling using its existing generation fleet, the RTO also is including units with signed generation interconnection agreements and projects approved under the 2015 Transmission Expansion Plan.

MISO Wants Reliability Provisions in State Plans

Meanwhile, Kari Bennett, MISO’s senior corporate counsel, said MISO’s comments to the EPA on the federal implementation plan (FIP) will focus on reliability.

In its comments, MISO said it would like EPA to authorize the use of a reliability safety valve in FIPs, similar to that in state implementation plans. MISO said EPA should allow a “meaningful, case-specific review of reliability that is comparable to the state plan requirement.” (See related story, FERC Outlines Principles for Clean Power Plan Analyses.)

Bennett said the comments do not get into the mechanics of how a safety valve would be developed or used.

“As we look at the situation, reliability is often case-specific and a sensitive issue,” she said. “We do think it is prudent for the EPA to include a reliability safety plan in the federal plan as well as state plans.”

FERC OKs MISO-SPP Transmission Settlement

By Amanda Durish Cook

FERC on Thursday approved MISO and SPP’s uncontested settlement agreement with a trio of orders governing how MISO transfers power between its North and South regions using SPP transmission.

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MISO North and South regions (Source: MISO)

FERC determined the settlement was “fair and reasonable and in the public interest” (ER14-1174, et al). The commission upheld a Jan. 5 settlement judge’s certification that the agreement was uncontested.

The RTOs agreed in October to the terms of the seven-year settlement, which stipulates north-to-south flows be capped at 3,000 MW and south to north be limited to 2,500 MW. (See SPP, MISO Reach Deal to End Transmission Dispute.) MISO and SPP have 45 days to file Tariff changes with FERC.

Two other orders dismissed all rehearing requests relating to issues prior to the settlement and approved the cancellation of SPP’s hurdle rate mechanism.

Clark Urges Caution

Commissioner Tony Clark wrote a concurring statement, saying the order “leaves the door open as to how the commission would analyze the settlement in the event a challenge is brought.”

Clark said the settlement puts new conditions on MISO’s transmission service because of the transfer limits established between MISO Midwest and MISO South.

“Because these terms could impact more than just the settling parties, including future MISO market participants, I do not think it is appropriate to extend the heightened Mobile-Sierra standard to those third parties or the commission acting [without formal prompting from another party]. Consistent with my prior statements, if we are to preserve the integrity of the Mobile-Sierra standard, we should be judicious in its application.”

The Mobile-Sierra doctrine, named after a pair of Supreme Court rulings, holds that negotiated contracts are presumed to be just and reasonable unless it “seriously harms the public interest” or the parties to the contract agree that the standard should not apply.

MISO, SPP Looking Forward

Jennifer Curran, MISO’s vice president of system planning and seams administration, said MISO was pleased with FERC’s approval. “With this issue behind us, we look forward to continued collaboration across our seams for the benefit of all our customers.”

SPP is “pleased to have the issue resolved,” said David Avery, SPP’s director of corporate communications.

As a result of the settlement, FERC moved to eliminate the $9.57/MWh hurdle rate on flows exceeding the 1,000-MW transfer limit per SPP and MISO’s joint operating agreement (ER16-56). MISO’s proposed Tariff revisions to replace the hurdle rate with a mutual compensation system will become effective Feb. 1.

“As explained by MISO, the substitution of the SPP service agreement with a payment structure for SPP’s and joint parties’ available system capacity obviates any need for the hurdle rate,” FERC said.

However, MISO’s proposed revisions to the commission failed to delete a few mentions of the SPP service agreement, as pointed out by MISO stakeholders. FERC directed MISO to remove the phrase and make a compliance filing in 30 days.

FERC also dismissed as moot requests for rehearing from MISO, MISO transmission owners and Entergy over now obsolete matters in the RTOs’ joint operating agreement (ER14-1174-001, et al).

Having made a one-time, $16 million payment to SPP to fund surplus flow charges over the past two years, MISO is continuing cost allocation talks (ER14-1736).

Beginning next month and continuing until February 2017, MISO will pay SPP $1.33 million per month to cover flows over the 1,000-MW contract path that cross MISO’s North-South interface, but MISO hasn’t yet determined a final cost allocation mechanism that would govern how the cost is split among MISO’s generation owners. (See “MISO to Begin SPP Settlement with $16 Million Payment,” MISO Market Subcommittee Briefs.)